Hydrocarbon-producing wells often are stimulated by hydraulic fracturing operations, wherein a servicing fluid such as a fracturing fluid or a perforating fluid may be introduced into a portion of a subterranean formation penetrated by a wellbore at a hydraulic pressure sufficient to create or enhance at least one fracture therein. Such a subterranean formation stimulation treatment may increase hydrocarbon production from the well.
In some wellbores, it may be desirable to individually and selectively create multiple fractures along a wellbore at a distance apart from each other, creating multiple “pay zones.” The multiple fractures should have adequate conductivity, so that the greatest possible quantity of hydrocarbons in an oil and gas reservoir can be produced from the wellbore. Some pay zones may extend a substantial distance along the length of a wellbore. In order to adequately induce the formation of fractures within such zones, it may be advantageous to introduce a stimulation fluid via multiple stimulation assemblies positioned within a wellbore adjacent to multiple zones. To accomplish this, it is necessary to configure multiple stimulation assemblies for the communication of fluid via those stimulation assemblies. Thus, there is an ongoing need to develop new methods and apparatuses to enhance hydrocarbon production.
A wellbore stimulation assembly allows a well producer to create an open well condition at an entry point in a zone by increasing pressure and opening ports in the tool to the formation. One such tool known in the art operates by a sliding sleeve that shears pins at an actuation pressure, thereby allowing the sliding sleeve to move to an open position. This single set point actuation methodology, however, prevents a casing pressure test at maximum operating pressure if the shear pin set value is less than the maximum operating pressure. Alternatively, if the shear pin set value is greater than the maximum operating pressure, than the operating pressure must exceed the maximum operating pressure in order to open the tool.
Moreover, shear pins do not always part at the exact set value, and sliding sleeve friction affects the overall activation pressure. Cemented applications pose a particular challenge, because cement causes additional friction for sliding sleeves, and any cavities or passages have a tendency to collect cement. When pins shear at a higher pressure than the designed pressure, maximum operating pressure may be exceeded and casing failure may result. When pins shear at a lower pressure than the design pressure, the tool opens prematurely before the well pressure testing and inspection is completed.